The accumulation of liquids in oil and natural gas wells restricts the flow of hydrocarbons from the producing formation into the bore hole. Reduced flow occurs when hydrostatic pressure exerted on the face of the producing formation reduces pressure drawdown, and liquids accumulated across from producing zones causes a reduction in gas or oil flow by saturating pore spaces with water or other liquids.
During the initial production period of a horizontal gas well, the gas velocity in the entire wellbore is sufficient to remove liquids from the well unassisted. As productivity naturally declines, there will eventually be insufficient pressure to overcome the hydrostatic head created by fluid accumulation in the vertical and horizontal sections of the well bore. Another contributing factor to gas well productivity decline is the accumulation of formation water or liquid hydrocarbons in the horizontal well bore across from gas productive perforations. This fluid accumulation will cause a reduction in gas relative permeability by saturating the pore throats near the wellbore with liquids. Similar effects occur in oil wells where water accumulates in the horizontal section, increasing hydrostatic pressure and decreasing oil relative permeability.
To maximize the returns from an oil/gas well, it is important to remove any restrictions to flow caused by wellbore liquids accumulation. When a well rate falls due to liquid loading, it is often necessary to periodically install mechanical equipment to remove liquid from the bore hole and reduce the hydrostatic head. This operation decreases the economic efficiency of the well, requires additional supervision, maintenance and equipment.
Several methods have been devised for removal of liquids from a bore hole, each having their own particular advantages and disadvantages. Usually a plunger is installed when a gas well has difficulty flowing naturally. This method lifts liquids from low rate gas wells by allowing the well to build pressure between flow cycles and lift complete slugs of liquid with each plunger stroke. The drawback to this technique is that during shut-in periods, accumulated liquids are driven back into the formation by pressure building in the tubing. Because the gas flow is intermittent, wellbore damage occurs during each shut-in period. Finally, a plunger cannot work consistently if the surface build-up pressure is not at least twice the line pressure that the well flows into. This method is not applicable for wells with significant deviation from a substantially vertical and linear wellbore configuration that restricts the free-fall of the plunger to the bottom of the well.
Another method of removing liquids is by pumping the liquid out of the casing with a long sucker rod operated by a pump jack at the surface. This method is not applicable for wells with significant deviation from a substantially vertical and linear wellbore configuration (also known as “doglegs”) that restrict the ability of the rod string to naturally fall on the downstroke. Deviations in the wellbore will cause wear on the rods and tubing during the upstroke. A modification of the sucker rod pumping method involves rotating progressive cavity pumps which use rotating rods and do not require a vertical return. This method also has drawbacks since rotating sucker rods will wear and break due to alternating bending stresses around the curves in a horizontal well. Downhole electric pumps use no rods but are inefficient in low liquid rate horizontal wells due to short run lives, gas locking and high equipment costs.
A method better suited for curved wellbores is known by those skilled in the art as “gas lift.” This widely used method involves injecting gas down one flow path with the intent of lightening the fluids returning up another flow path. This gasification reduces the density of the produced fluids and facilitates the flow to the surface as long as reservoir pressure remains high enough to lift the gasified column of fluid.
“Continuous” and “intermittent” are the two classes of gas lift. In continuous gas lift installations, lift gas is continuously injected into the annulus, flowing down to a port at the bottom of the well, and returning up a second conduit with the produced fluids. For intermittent gas lift installations, the well is produced without injecting gas until liquid accumulation causes a reduction in flow capacity. Then, gas is injected into the annular space to re-start flow. Lift gas is removed once the well can flow unassisted.
Chamber lift is a specialized form of intermittent gas lift where an accumulation chamber is used to collect a designated volume of liquid in a fixed chamber, one side of a concentric string, or the bottom of a U-tube in a vertical wellbore. This accumulated liquid is periodically circulated to the surface using pressurized gas introduced into one conduit of the u-tube or concentric string at the surface, forcing the liquids up the other side.
A device patented by Buckman discussed in U.S. Pat. No. 5,006,046 is a downhole U-tube designed exclusively for vertical wells and is actuated with pressure in the flowing wellbore. Since the system is driven by formation pressure, a high formation pressure is required to lift a complete slug of liquid to the surface. High formation pressure is rarely present in mature gas wells.
The typical lack of high formation pressure was addressed by Reitz (U.S. Pat. Nos. 6,672,392 and 7,100,695) using one small conduit fully contained within a second, larger concentric conduit with the liquid intake port at the extreme end. Using high pressure gas delivered at the surface, this device is designed to lift liquids from the bottom of a vertical wellbore. This method may be applied to horizontal wells but the method is limited by the amount of liquid that can be accumulated per cycle since the liquid intake is at the bottom of the device and no liquid accumulation is possible toward the toe of the wellbore. The Reitz disclosures also do not provide a means of venting gas bubbles that will limit liquid accumulation. Furthermore, the amount of liquid that can be collected is limited to the volume that can be contained in the relatively small diameter pipe over a few hundred feet of length.
Another enhancement to the Buckman system was described by Lima in U.S. Pat. No. 5,671,813 where two production strings are used to lift a vertical well using a circulating mechanical interface. This system is limited by the inability to lift from around the heel of a horizontal well since the liquid intake is at the extreme end of the apparatus, and the only area for accumulation of liquids is again the amount that can be lifted by reservoir pressure toward the wellhead.